Summary of IVANHOE ENERGY INC

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

With the exception of historical information, certain matters discussed in this Form 10-Q are forward looking statements that involve risks and uncertainties. Certain statements contained in this Form 10-Q, including statements which may contain words such as "could", "should", "expect", "believe", "will" and similar expressions and statements relating to matters that are not historical facts are forward-looking statements. Such statements involve known and unknown risks and uncertainties which may cause our actual results, performances or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Although we believe that our expectations are based on reasonable assumptions, we can give no assurance that our goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include, but are not limited to, our ability to raise capital as and when required, the timing and extent of changes in prices for oil and gas, competition, environmental risks, drilling and operating risks, uncertainties about the estimates

of reserves and the potential success of heavy-to-light and gas-to-liquids development technologies, the prices of goods and services, the availability of drilling rigs and other support services, legislative and government regulations, political and economic factors in countries in which we operate and implementation of our capital investment program.

The following should be read in conjunction with the Company's consolidated financial statements contained herein and in the Form 10K for the year ended December 31, 2003, along with Management's Discussion and Analysis of Financial Condition and Results of Operations contained in such Form 10K. Any terms used but not defined in the following discussion have the same meaning given to them in the Form 10K.

Results of Operations

For the three-month period ended June 30, 2004, the net loss was $1.3 million ($0.01 per share) compared to a net loss of $4.6 million ($0.03 per share) for the same period in 2003. The net loss for the six-month period ended June 30, 2004 was $2.6 million ($0.02 per share) compared to a net loss of $5.7 million ($0.04 per share) for the same period in 2003. The net loss for the three-month and six-month periods ended June 30, 2003 include a $3.3 million ($0.02 per share) write down of our investment in the Qatar gas-to-liquids (GTL) project as a result of the termination of contract negotiations in May 2003.

Cash from operating activities for the three-month and six-month periods ended June 30, 2004 was $1.3 million compared to cash from operating activities of $0.9 million and $1.2 million for the same periods in 2003. Our cash position increased $15.9 million for the first six months of 2004 primarily due to net proceeds of $20.4 million received from private placements in the first quarter of 2004, $20.0 million from Richfirst related to its farm-in to the Dagang oil project development program, $2.0 million in proceeds from the Wells Fargo loan related to the development of our South Midway field and $1.4 million from the exercise of stock options. This is partially offset by $25.4 million for capital spending for the first six months of 2004 and $2.5 million paid to Ensyn under our agreements with that company. Our cash position decreased $1.1 million for the comparable period in 2003 primarily due to $4.1 million of net cash required for capital spending partially offset by $1.2 million in cash from operating activities and an increase in notes payable of $1.8 million.

Production and Operations

Oil and gas revenues for the three-month and six-month periods ended June 30, 2004 were $3.5 million and $6.8 million, respectively. This represents increases of $1.1 million and $1.9 million from the comparable periods in 2003. Half of the increase in revenue for the three-month period ended June 30, 2004 is due to a 21% or $5.68 per boe increase in oil and gas prices from the comparable period in 2003. Increases in production volumes account for the remaining 50% increase in revenues as a result of additional development programs initiated in 2003 at the South Midway and Daqing fields and the start up of production in 2004 at our Citrus and Knights Landing fields. Production volumes from the Dagang field development, initiated at the end of 2003, increased 44% from the comparable period in 2003 but these increases are mostly offset by CITIC's participation in its 40% share of production related to finalizing the farm-out agreement in the second quarter of 2004. The increase in revenues for the six-month period ended June 30, 2004 was mainly due to more than a four-fold increase in production volumes from the Daqing field, in which we own a royalty interest, in addition to increases in production from the southern expansion of our South Midway field and the start up of production operations at our Citrus and Knights Landing fields in 2004. Additionally, a 16% or $4.36 per boe increase in oil and gas prices contributed to a 45% increase in revenues for the six-month period ended June 30, 2004.

Operating costs decreased 5% or $0.37 per boe for the three-month period ended June 30, 2004 compared to the same period in 2003. Operating costs in China decreased 17% or $1.51 per boe for the second quarter of 2004 due mainly to a reduction in well workovers and decreased power costs in 2004. Operating costs in the U.S. increased 6% or $0.47 per boe for the second quarter of 2004 as compared to the same period in 2003 due mainly to the start up of production operations at our Knights Landing and Sledge Hamar fields partially offset by a reduction in workover costs at our Spraberry field. For the six-month period ended June 30, 2004, operating costs increased 10% or $0.75 per boe compared to the same period in 2003. Operating costs in China decreased 8% or $0.59 per boe due mainly to a reduction in well workovers and decreased power costs during the second quarter of 2004. Operating costs in the U.S. increased 26% or $1.76 per boe for the six-month period ended June 30, 2004 due mainly to an increase in costs incurred for the cyclic steam operations in the southern expansion of South Midway in the first quarter of 2004 and the start up of production operations at our Citrus, Knights Landing and Sledge Hamar fields during 2004. This is partially offset by a reduction in workover costs at our Spraberry field from the comparable period in 2003.

Our depletion rate increased $5.39 and $4.33 per boe for the three-month and six-month periods ended June 30, 2004, respectively, compared to the same periods in 2003. The depletion rate in China increased $2.07 and $1.96 per boe for the three-month and six-month periods ended June 30, 2004, respectively, due mainly to anticipated increases in Dagang future development costs. The depletion rate in the U.S. increased $7.86 and $6.22 per boe for the three-month and six-month periods ended June 30, 2004, respectively, due mainly to an increase in the carrying costs of our evaluated U.S. oil and gas assets during the fourth quarter of 2003 primarily in Northwest Lost Hills, East Texas and North South Forty. In addition, the increase in the U.S. depletion rate for the three-month period ended June 30, 2004 is due to an increase in Knights Landing exploration costs and a decrease in estimated reserves for Knights Landing a result of reduced success in the current exploration drilling program as five dry holes had been drilled as at June 30, 2004.

Production and operating information are detailed below:

                                              Three-Month Periods Ended June 30,
                         ----------------------------------------------------------------------------
                                         2004                                    2003
                         -------------------------------------   ------------------------------------
                            U.S.        China         Total         U.S.        China        Total
                         ----------   ----------   -----------   ----------   ----------   ----------
  Net Production:
  BOE                      60,848       45,502       106,350       49,806       36,698       86,504
  BOE/day for the year        669          500         1,169          547          403          950



                                              Per BOE                             Per BOE
                                 ---------------------------------   ---------------------------------
  Oil and gas revenue            $ 32.97     $ 32.21     $ 32.65     $ 25.04     $ 29.55     $ 26.96
                                   -----       -----       -----       -----       -----       -----

  Operating costs                   7.87        7.17        7.57        7.40        8.68        7.94
  Production taxes                  1.12           -        0.64        0.98           -        0.57
  Engineering support               2.12        3.38        2.66        1.87        3.22        2.44
                                   -----       -----       -----       -----       -----       -----

                                   11.11       10.55       10.87       10.25       11.90       10.95
                                   -----       -----       -----       -----       -----       -----

  Net Revenue before depletion     21.86       21.66       21.78       14.79       17.65       16.01
  Depletion                        15.85       11.01       13.78        7.99        8.94        8.39
                                   -----       -----       -----       -----       -----       -----

  Net Revenue from operations    $  6.01     $ 10.65     $  8.00     $  6.80     $  8.71     $  7.62
                                   -----       -----       -----       -----       -----       -----

                                               Six-Month Periods Ended June 30,
                        -------------------------------------------------------------------------------
                                         2004                                     2003
                        --------------------------------------   --------------------------------------
                           U.S.         China         Total         U.S.         China         Total
                        -----------   ----------   -----------   -----------   ----------   -----------
 Net Production:
 BOE                      119,214       95,864       215,078       105,783       73,757       179,540
 BOE/day for the year         655          527         1,182           584          407           991



                                              Per BOE                             Per BOE
                                 ---------------------------------   ---------------------------------
  Oil and gas revenue            $ 31.88     $ 30.92     $ 31.45     $ 25.42     $ 29.48     $ 27.09
                                   -----       -----       -----       -----       -----       -----

  Operating costs                   8.51        7.28        7.96        6.75        7.87        7.21
  Production taxes                  1.15           -        0.64        0.95           -        0.56
  Engineering support               2.34        3.15        2.70        1.87        3.40        2.50
                                   -----       -----       -----       -----       -----       -----

                                   12.00       10.43       11.30        9.57       11.27       10.27
                                   -----       -----       -----       -----       -----       -----

  Net Revenue before depletion     19.88       20.49       20.15       15.85       18.21       16.82
  Depletion                        15.11       11.22       13.37        8.89        9.26        9.04
                                   -----       -----       -----       -----       -----       -----

  Net Revenue from operations    $  4.77     $  9.27     $  6.78     $  6.96     $  8.95     $  7.78
                                   -----       -----       -----       -----       -----       -----

Changes in Non-Cash Working Capital

Non-cash working capital increased $6.2 million and $5.4 million for the three-month and six-month periods ended June 20, 2004, respectively, compared to increases of $1.8 million and $2.4 million for the same periods in 2003. The increases in non-cash working capital for investing activities for the three-month and six-month periods ended June 20, 2004 are mainly due to increases of $6.4 million and $6.3 million, respectively, in our payables and accruals as a result of our capital programs in China and the U.S. The increase in non-cash working capital for investing activities for the three-month and six-month periods ended June 30, 2004 is partially offset by increases of $0.8 million and $1.1 million, respectively, in accounts receivable primarily as a result of advances made to our joint venture partners to fund our U.S. development and Iraq EOR activities.

Exploration and Development Activities

Capital spending on exploration and development activities for the three-month and six-month periods ended June 30, 2004 was $14.1 million and $24.2 million, respectively, an increase of $11.5 million and $19.8 million from the amounts spent during the comparable periods in 2003. This increase is due mainly to our development programs in our Dagang, Citrus and Knights Landing fields and our Zitong seismic acquisition program in China.

Capital spending at Dagang increased $3.3 million and $7.1 million during the three-month and six-month periods ended June 30, 2004, respectively, compared to the same periods in 2003. By the end of the second quarter of 2004, we had drilled seven development wells in Dagang, four of which are on production and the remaining three wells are in various stages of completion or testing. Three drilling rigs are now under contract for the Dagang project and the development program is on schedule for a year-end 2004 gross production target of 2,500 bopd. Over the next three years, we expect to drill 115 new wells and work over 28 existing wells.

During the second quarter of 2004, we completed phase one of our 1,100-kilometer seismic acquisition program in the Zitong project, which increased our capital spending for the three-month and six-month periods ended June 30, 2004 by $3.0 million and $5.0 million, respectively, compared to the same periods in 2003. In our Zitong project we are continuing with the interpretation of the seismic and plan to drill one exploration well in late 2004.

We farmed into the Knights Landing gas project in northern California in February 2004, which resulted in increases of $2.9 million and $4.4 million in our capital spending program for the first three-month and six-month periods ended June 30, 2004, respectively, compared to the same periods in 2003. We acquired a 50% non-operating interest in four gas wells in that area and agreed to fund the cost of a gas gathering and surface facilities system to the four wells at a combined cost of $1.6 million. We also hold a 50% interest in 14,000 acres of leases in the surrounding area for further exploration drilling. In May 2004, the pipeline gathering system and facilities were completed and the four gas wells were placed on production. In late May 2004, the 10 well drilling program commenced. Nine of the 10 wells have been drilled resulting in three gas discoveries and 6 dry holes. The three gas discoveries have been tested and are now being tied in to the gathering system. The final well remains to be drilled under the initial drilling program, and we are evaluating drilling additional follow up wells to develop the three discoveries drilled thus far.

Development of our Citrus field increased our capital spending program $1.6 million and $2.4 million during the three-month and six-month periods ended June 30, 2004, respectively, compared to the same periods in 2003. After having placed Citrus #1 on production in January 2004, additional work was conducted on the well in the second quarter of 2004 to add the Lower Reef Ridge zone to the existing horizontal Antelope zone. Both zones are currently flowing about 50 barrels of oil per day. A downhole pump will be installed in the near future to increase total rates. The Citrus #2 well is currently being completed in four combined oil zones with fracture stimulation of each interval. The Citrus #3 well has finished drilling and should be completed by mid-August. We plan to observe production for a few months prior to resuming development of this area to determine the best drilling and completion methods.

In January 2004, we farmed into the LAK Ranch Field, a thermal recovery/horizontal well oil project in Weston County, Wyoming. Facility modifications for the pilot phase were completed in the second quarter of 2004 increasing our capital spending program $0.3 million and $0.8 million for the three-month and six-month periods ended June 30, 2004, respectively, compared to the same periods in 2003. The first cycle of steam injection into the horizontal producer was completed by the end of May 2004. Approximately 70% of the steam has been recovered to date and oil cuts are improving as anticipated. The oil is high-quality, 19-degree API gravity, and contains high levels of naphtha. Plans are underway to commence a second steam cycle in the third quarter of 2004, using a larger quantity of steam at a higher pressure to further stimulate oil production. Progress continues with the planned ultra-high resolution 3D seismic survey scheduled for the last quarter of 2004. The survey is designed to provide the necessary detail for targeting future horizontal well development at LAK Ranch. After completion of the 3D seismic survey we plan to drill additional delineation wells to prove up oil-in-place reserves and commerciality of a full steam injection project. Following completion of the pilot phase, the development program is scheduled to include additional horizontal producing wells, new steam injection wells and the extension of surface facilities. We estimate that, at the low end of the recovery range, the initial development program could grow to more than 20 producing wells. During the pilot phase, we will have an initial 30% working interest. Should we decide to enter the next two phases of the contract, our working interest will increase to a maximum of 60%. Should we elect not to proceed beyond the pilot phase, our working interest will be reduced to 15% and we would no longer be the operator.

Capital spending in South Midway decreased $0.2 million and $0.6 million during the three-month and six-month periods ended June 30, 2004, respectively, compared to the same periods in 2003 due mainly to the completion of the construction of our facilities for the first phase of the southern expansion in the third quarter of 2003. We drilled five delineation wells in South Midway in the second quarter of 2003 compared to six delineation wells and one exploratory well in the second quarter of 2004, resulting in the completion of four producing oil wells. The production from the southern expansion area is showing more favorable response to steam with total South Midway production currently averaging about 600 barrels of oil per

day compared to an average of 530 barrels of oil per day for the second quarter of 2004. We will monitor production from the southern expansion area to determine optimum well locations before resuming development. We have 55 producing wells in South Midway, with a working interest of 100%.

Exploration and development of Sledge Hamar increased our capital spending program $0.3 million and $0.4 million during the three-month and six-month periods ended June 30, 2004, respectively, compared to the same periods in 2003. We have one producing discovery well, the Sledge Hamar 1-7 with a working interest of 40%. A second appraisal well, the Sledge Hamar 2-7, was drilled in May 2004 and was unsuccessful in establishing production from the Stevens sand that produces in the Sledge Hamar 1-7 well. We are evaluating a test program for shallower Diatomite zones where shows were encountered in the Sledge Hamar 2-7 well. The Diatomite is a producing formation in the adjacent South Belridge field. Follow up wells may be drilled in the latter part of 2004 to further develop both the Stevens and the Diatomite zones.

Our capital spending program for the remainder of 2004 also includes additional North South Forty wells in the San Joaquin Valley of California and Malakoff and Catfish Creek wells in East Texas as follows:

We hold a 50% working interest in two shallow gas prospects that have been defined in the North South Forty seismic area as a result of an extensive 3-D seismic acquisition program conducted on lands west of the Belridge oil field. In May 2004, we drilled the first prospect to 1,500 feet resulting in increase in capital spending of $0.1 million for the three-month and six-month periods ended June 30, 2004. The well was a dry hole and was abandoned. The second of the two prospects will be drilled in the third quarter of 2004. In addition, we hold a 100% working interest in a third oil and gas prospect in the North South Forty seismic area. We plan to drill a 3,500 foot well late in 2004. We are currently seeking a partner to participate with us in the latter prospect.

In East Texas, we plan to farm-out the drilling of one well each in the Malakoff and Catfish Creek prospects in which we have a 25% carried interest. The Malakoff well is planned to be drilled to a depth of 8,700 feet and the Catfish Creek well to a depth of 11,000 feet.

Heavy-to-Light Activities

In January 2004, we signed a Stock Purchase and Shareholders' Agreement with Ensyn Group Inc. ("Ensyn Group") and its subsidiary, Ensyn Petroleum International Ltd. ("Ensyn"), pursuant to which, for a total payment of $2 million, we acquired a 10% equity interest in Ensyn and exclusive rights to use the proprietary Ensyn RTPTM Process in several key international markets.

In April 2004, we signed an agreement with Ensyn Group and Ensyn pursuant to which we advanced Ensyn an additional $1.0 million in consideration for the right to elect to either take an additional 5% equity interest in Ensyn or consider the advance as a loan to be repaid with interest over a period of 90 days commencing on July 31, 2005.

Ensyn is currently installing a commercial demonstration facility in the South Belridge field near Bakersfield, California to demonstrate the commercial viability of the Ensyn RTPTM Process at the facility in mid-September, 2004.

The Ensyn RTPTM Process upgrades the quality of heavy oil by producing lighter, more valuable crude oil. Ensyn reports that this process yields up to a three-fold economic improvement in heavy-oil projects. The heaviest hydrocarbon fraction is consumed as fuel to

generate the steam used to enhance recovery of heavy crude. This lowers costs by reducing or eliminating the need to purchase high-priced natural gas for steam generation and improves revenue since the higher quality light-crude fraction can be sold at higher prices. The lighter crude has improved viscosity that permits more efficient pumping through pipeline networks and significantly reduces transportation costs to marketing points. The Ensyn RTPTM Process uses readily available plant and process components. The technology already has been successfully applied to continuous wood/biomass processing, with several commercial plants in operation in Canada and the U.S. An Ensyn pilot plant in Ontario, Canada, has completed more than 90 test runs on heavy oil.

We have exclusive rights to use the Ensyn RTPTM Process in China, Mongolia, Iraq, Oman and all countries in South America except Venezuela. In these countries, our rights will be exclusive for an initial term of five years subject to extension if and when commercial plants are constructed. We have non-exclusive rights to the process in other countries. For each project we develop using the Ensyn RTPTM Process, Ensyn may elect to receive an equity participation in the project for the same proportionate cost as paid by the Company. The participation that may be obtained by Ensyn is no more than 10%, except for each such project that we develop in South America, other than in Venezuela and Peru, where Ensyn may elect to receive an equity interest equal to 25% of our interest. Ensyn's equity position will offset and eliminate the payment of license fees for use of the Process in the project.

Gas-to-Liquids Activities

There was no additional capital spending on GTL projects for the three-month period ended June 30, 2004.

In the second quarter of 2004, we wrote down our $0.3 million investment in the Oman GTL project as our opportunity to build a 45,000 bpd GTL fuels plant in Oman failed to materialize due to a lack of sufficient uncommitted gas volumes to support a 45,000 bpd GTL plant in Oman.

Although our proposal for a 45,000-barrels per day GTL plant in Egypt is still under consideration by the government of Egypt, and its agencies responsible for the development and monetization of its natural gas reserves, the government is currently evaluating alternatives for monetization of its uncommitted gas reserves including pipelines to neighboring countries and liquid natural gas plants. We await the outcome of their evaluations.

We have completed the initial phase of the commercialization study for the GTL plant in Bolivia. The results indicate that under the current tax regulations pertaining to the Bolivian hydrocarbon sector, a 90,000 barrel-per-day GTL plant could be commercial in the southern region of Bolivia. However, given the current political climate and the uncertainty surrounding the impact that newly proposed tax regulations could have on the viability of a GTL plant, we, and our partners in the commercialization study, have elected not to proceed any further until all hydrocarbon legislation has been finalized which is expected during the third quarter of 2004.

EOR

Capital spending on EOR related activities for the three-month and six-month periods ended June 30, 2004 was $0.8 million and $1.2 million, respectively. Several of our senior executives and technical personnel have had prior experience working on oil projects at various fields in Iraq. We are utilizing this prior experience and the experience of consultants with extensive knowledge of, and background in, Iraq to plan and pursue development

activities that, if successful, would result in increased oil production and reserves in that country.

Liquidity and Capital Resources

As at June 30, 2004, our cash position was $30.4 million as a result of closing two special warrant financings in the first quarter of 2004, which generated net proceeds of $20.4 million, we received $20.0 million from Richfirst related to their 40% farm-in to the Dagang oil project development program and $2.0 million in proceeds from the Wells Fargo loan related to the development of our South Midway field. We borrowed the final $2.0 million on the Wells Fargo loan in July 2004 bringing the total loan amount to $5.0 million.

The budget for our capital program for the remainder of 2004, is estimated to be $28.5 million. Our current cash position, expected cash flows, bank credit . . .